Common Stock, without par value (4,958,598,361 sharesoutstanding at January 31, 2011)

New York Stock Exchange

Registered securities guaranteed by Registrant:

SeaRiver Maritime Financial Holdings, Inc.

Twenty-Five Year Debt Securities due October 1, 2011

New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ü No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes No ü

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ü No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ü No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ü

Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of
the Exchange Act.

Large accelerated filer
ü Accelerated filer

Non-accelerated filer
Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the
Act). Yes No ü

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2010, the last business day of
the registrants most recently completed second fiscal quarter, based on the closing price on that date of $57.07 on the New York Stock Exchange composite tape, was in excess of $290 billion.

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of
the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a
major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. ExxonMobil also has interests in electric power generation facilities.
Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.

Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso or Mobil. For convenience and simplicity, in this report the
terms ExxonMobil, Exxon, Esso and Mobil, as well as terms like Corporation, Company, our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning
depends on the context in question.

On June 25,
2010, ExxonMobil acquired XTO Energy Inc. (XTO) by merging a wholly-owned subsidiary of ExxonMobil with and into XTO (the merger), with XTO continuing as the surviving corporation and a wholly-owned subsidiary of ExxonMobil.
Each share of XTO common stock was converted into the right to receive 0.7098 shares of common stock of ExxonMobil plus cash in lieu of fractional shares. The merger combines XTOs high-quality unconventional gas and oil shale reserve base and
technical expertise in unconventional development with ExxonMobils research and development expertise, project management and operational skill, global scale, and financial capacity. Details of the merger transactions are contained in the
Financial Section of this report under the following: Note 19: Acquisition of XTO Energy Inc.

Throughout ExxonMobils businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air,
water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to monitor and reduce nitrogen oxide, sulfur oxide, and greenhouse gas emissions and expenditures for
asset retirement obligations. ExxonMobils 2010 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobils share of equity company expenditures, were about $4.5 billion, of which
$1.9 billion were capital expenditures and $2.6 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2011 and 2012 (with capital expenditures approximately 40 percent of the total).

The energy and petrochemical industries are
highly competitive. There is competition within the industries and also with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers. The Corporation competes with other firms in the sale or
purchase of needed goods and services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes.

Operating data and industry segment information for the
Corporation are contained in the Financial Section of this report under the following: Quarterly Information, Note 17: Disclosures about Segments and Related Information and Operating Summary. Information on
oil and gas reserves is contained in the Oil and Gas Reserves part of the Supplemental Information on Oil and Gas Exploration and Production Activities portion of the Financial Section of this report.

ExxonMobil has a long-standing commitment to the development
of proprietary technology. We have a wide array of research programs designed to meet the needs identified in each of our business

segments. Information on Company-sponsored research and development spending is contained in Note 3: Miscellaneous Financial Information of the Financial Section of this report.
ExxonMobil held approximately 11 thousand active patents worldwide at the end of 2010. For technology licensed to third parties, revenues totaled approximately $125 million in 2010. Although technology is an important contributor to the overall
operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.

The number of regular employees was 83.6 thousand, 80.7 thousand and 79.9 thousand at years ended 2010, 2009
and 2008, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporations benefit plans and
programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 20.1 thousand, 22.0 thousand and 24.8 thousand at years ended 2010, 2009 and 2008, respectively.

Information concerning the source and availability of raw
materials used in the Corporations business, the extent of seasonality in the business, the possibility of renegotiation of profits or termination of contracts at the election of governments and risks attendant to foreign operations may be
found in Item 1ARisk Factors and Item 2Properties in this report.

ExxonMobil maintains a website at exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or
furnish the reports to the Securities and Exchange Commission. Also available on the Corporations website are the Companys Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the audit,
compensation and nominating committees of the Board of Directors. Information on our website is not incorporated into this report.

Item 1A.

Risk Factors.

ExxonMobils financial and operating results are
subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses. Many of these risk factors are not within the Companys control and could adversely affect our business, our financial and operating results or our
financial condition. These risk factors include:

Supply and
Demand.

The oil, gas, and petrochemical
businesses are fundamentally commodity businesses. This means ExxonMobils operations and earnings may be significantly affected by changes in oil, gas and petrochemical prices and by changes in margins on refined products. Oil, gas,
petrochemical and product prices and margins in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity.

Economic conditions. The
demand for energy and petrochemicals correlates closely with general economic growth rates. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors
that affect general economic conditions in the world or in a major region, such as changes in population growth rates or periods of civil unrest, also impact the demand for energy and petrochemicals. Economic conditions that impair the functioning
of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our financial assets and to the ability of our partners and customers to fulfill their commitments to ExxonMobil.

Other demand-related factors. Other factors that may
affect the demand for oil, gas and petrochemicals, and therefore impact our results, include technological improvements in energyefficiency; seasonal weather patterns, which affect the demand for energy associated with heating and
cooling; increased competitiveness of alternative energy sources that have so far generally not been competitive with oil and gas without the benefit of government subsidies or mandates; and changes in technology or consumer preferences that alter
fuel choices, such as toward alternative fueled vehicles.

Other supply-related factors. Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the
development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in
industry refining or petrochemical manufacturing capacity tend to reduce margins on the affected products. World oil, gas, and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member
countries to OPEC production quotas and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors operations, or unexpected unavailability of distribution channels that may disrupt supplies. Technological change
can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.

Other market factors. ExxonMobils business results are also exposed to potential negative
impacts due to changes in currency exchange rates, interest rates, inflation, and other local or regional market conditions. We generally do not use financial instruments to hedge market exposures.

Government and Political Factors.

ExxonMobils results can be adversely affected by
political or regulatory developments affecting our operations.

Access limitations. A number of countries limit access to their oil and gas resources, or may place resources off-limits from development altogether. Restrictions on
foreign investment in the oil and gas sector tend to increase in times of high commodity prices, when national governments may have less need of outside sources of private capital. Many countries also restrict the import or export of certain
products based on point of origin.

Restrictions on doing business. As a U.S. company, ExxonMobil is subject to laws prohibiting U.S.
companies from doing business in certain countries, or restricting the kind of business that may be conducted. Such restrictions may provide a competitive advantage to our non-U.S. competitors unless their own home countries impose comparable
restrictions.

Lack of legal
certainty. Some countries in which we do business lack well-developed legal systems, or have not yet adopted clear regulatory frameworks for oil and gas development. Lack of legal certainty exposes our operations to
increased risk of adverse or unpredictable actions by government officials, and also makes it more difficult for us to enforce our contracts. In some cases these risks can be partially offset by agreements to arbitrate disputes in an international
forum, but the adequacy of this remedy may still depend on the local legal system to enforce an award.

Regulatory and litigation risks. Even in countries with well-developed legal systems where ExxonMobil
does business, we remain exposed to changes in law (including changes that result from international treaties and accords) that could adversely affect our results, such as increases in taxes or government royalty rates (including retroactive
claims); price controls; changes in environmental regulations or other laws that increase our cost of compliance or reduce or delay available business opportunities (including changes in laws related to offshore drilling operations, water use, or
hydraulic

fracturing); adoption of regulations mandating the use of alternative fuels or uncompetitive fuel components; government actions to cancel contracts or renegotiate terms unilaterally; and
expropriation. Legal remedies available to compensate us for expropriation or other takings may be inadequate. We also may be adversely affected by the outcome of litigation or other legal proceedings, especially in countries such as the United
States in which very large and unpredictable punitive damage awards may occur.

Security concerns. Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, and other local security
concerns. Such concerns may require us to incur greater costs for security or to shut down operations for a period of time.

Climate change and greenhouse gas restrictions. Due to concern over the risk of climate change, a
number of countries have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These include adoption of cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards,
and incentives or mandates for renewable energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shifting hydrocarbon demand toward relatively
lower-carbon sources such as natural gas. Current and pending greenhouse gas regulations may also increase our compliance costs, such as for monitoring or sequestering emissions.

Government sponsorship of alternative
energy. Many governments are providing tax advantages and other subsidies and mandates to make alternative energy sources more competitive against oil and gas. Governments are also promoting research into new
technologies to reduce the cost and increase the scalability of alternative energy sources. We are conducting our own research efforts into alternative energy, such as through sponsorship of the Global Climate and Energy Project at Stanford
University and research into hydrogen fuel cells and fuel-producing algae. Our future results may depend in part on the success of our research efforts and on our ability to adapt and apply the strengths of our current business model to providing
the competitive energy products of the future. See Management Effectiveness below.

Management Effectiveness.

In addition to external economic and political factors, our future business results also depend on our ability to manage successfully those factors that are at least in part within our control. The extent
to which we manage these factors will impact our performance relative to competition. For projects in which we are not the operator, we depend on the management effectiveness of one or more coventurers whom we do not control.

Exploration and development
program. Our ability to maintain and grow our oil and gas production depends on the success of our exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most
promising resource prospects and apply our project management expertise to bring discovered resources on line on schedule.

Project management. The success of ExxonMobils Upstream, Downstream, and Chemical businesses
depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability
to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of
effective spot markets; manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; prevent, to the extent possible, and respond effectively to unforeseen technical
difficulties that could delay project startup or cause unscheduled

project downtime; and influence the performance of project operators where ExxonMobil does not perform that role.

Operational
efficiency. An important component of ExxonMobils competitive performance, especially given the commodity-based nature of many of our businesses, is our ability to operate efficiently, including our ability to
manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements and regular reappraisal of our asset portfolio.

Research and
development. To maintain our competitive position, especially in light of the technological nature of our businesses and the need for continuous efficiency improvement, ExxonMobils research and development
organizations must be successful and able to adapt to a changing market and policy environment.

Safety, business controls, and environmental risk management. Our results depend on managements ability to minimize the inherent risks of oil, gas, and
petrochemical operations and to control effectively our business activities. We apply rigorous management systems and continuous focus to workplace safety and to avoiding spills or other adverse environmental events. For example, we work to minimize
spills through a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. Similarly, we are implementing cost-effective new technologies and adopting
new operating practices to reduce air emissions, not only in response to government requirements but also to address community priorities. We also maintain a disciplined framework of internal controls and apply a controls management system for
monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result if our management systems and controls do not function as intended. The ability to insure against such risks is limited by the capacity of the
applicable insurance markets, which may not be sufficient.

Preparedness. Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For example, hurricanes may damage our
offshore production facilities or coastal refining and petrochemical plants in vulnerable areas. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our rigorous disaster preparedness and response
planning, as well as business continuity planning.

Projections, estimates and descriptions of ExxonMobils plans and objectives included or incorporated in Items 1, 1A, 2, 7 and 7A of
this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs and business plans could differ materially due to, among other things, the factors discussed above
and elsewhere in this report.

The table below summarizes the
oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each
month during the last 12-month period. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favorable or adverse event has occurred since December 31, 2010, that would cause a
significant change in the estimated proved reserves as of that date.

Liquids(1)

Bitumen

SyntheticOil

NaturalGas

Oil-EquivalentBasis

(million bbls)

(million bbls)

(million bbls)

(billion cubic ft)

(million bbls)

Proved Reserves

Developed

Consolidated Subsidiaries

United States

1,478





15,344

4,035

Canada/South America(2)

133

519

681

1,077

1,512

Europe

361





3,516

947

Africa

1,055





711

1,174

Asia

1,306





6,593

2,405

Australia/Oceania

139





1,174

335

Total Consolidated

4,472

519

681

28,415

10,408

Equity Companies

United States

271





97

287

Europe

21





8,167

1,382

Asia

1,623





20,494

5,039

Total Equity Company

1,915





28,758

6,708

Total Developed

6,387

519

681

57,173

17,116

Undeveloped

Consolidated Subsidiaries

United States

474





10,650

2,249

Canada/South America(2)

30

1,583



181

1,643

Europe

62





526

150

Africa

744





197

777

Asia

717





667

828

Australia/Oceania

136





6,177

1,165

Total Consolidated

2,163

1,583



18,398

6,812

Equity Companies

United States

80





20

83

Europe

10





2,579

440

Asia

250





645

358

Total Equity Company

340





3,244

881

Total Undeveloped

2,503

1,583



21,642

7,693

Total Proved Reserves

8,890

2,102

681

78,815

24,809

(1)

Liquids includes crude, condensate and natural gas liquids.

(2)

South America includes developed proved reserves of 0.6 million barrels of liquids and 97 billion cubic feet of natural gas and undeveloped proved reserves of 0.6
million barrels of liquids and 66 billion cubic feet of natural gas.

In the preceding reserves information, consolidated subsidiary and equity company reserves
are reported separately. However, the Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.

The Corporations overall volume capacity outlook, based
on projects coming on stream as anticipated, is for production capacity to grow over the period 2011-2015. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir
performance, regulatory changes, asset sales, weather events, price effects on production sharing contracts and other factors as described in Item 1ARisk Factors of this report.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing
process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines. Furthermore, the Corporation only records proved reserves for projects
which have received significant funding commitments by management made toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a
number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long-term oil and gas price levels.

B. Technologies Used in Establishing Proved Reserves Additions in 2010

Additions to ExxonMobils proved reserves in 2010 were
based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent
results.

Data used in these integrated
assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance
information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 2-D and 3-D seismic data, calibrated with available well control information. Where applicable, surface geological
information was also utilized. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software and commercially available data analysis packages.

In some circumstances, where appropriate analog reservoirs
were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.

C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves

ExxonMobil has a dedicated Reserves Technical Oversight
group that is separate from the operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regulations, review of annual
changes in reserves estimates, and the reporting of ExxonMobils proved reserves. This group also maintains the official company reserves estimates for ExxonMobils proved reserves of crude and natural gas liquids, bitumen, synthetic oil
and natural gas. In addition, the group provides training to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The group is managed by and staffed with individuals that have an average of more
than 20 years of technical experience in the petroleum industry, including expertise in the classification and categorization of reserves under the SEC guidelines. This group includes several individuals who hold advanced degrees in either
Engineering or Geology, as well as individuals who hold Bachelors degrees in various technical disciplines. Several members of the group hold professional registrations in their field of expertise and several have served on the Oil and Gas
Reserves Committee of the Society of Petroleum Engineers.

The Reserves Technical Oversight group maintains a central computerized database containing
the official company global reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central computerized database. An annual review of the
systems controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. No changes may be made to the reserves
estimates in the central database, including additions of any new initial reserves estimates or subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized personnel within the operating organization. In
addition, changes to reserves estimates that exceed certain thresholds require further review and approval of the appropriate level of management within the operating organization before the changes may be made in the central database. Endorsement
by the Reserves Technical Oversight group for all proved reserves changes is a mandatory component of this review process. After all changes are made, reviews are held with senior management for final endorsement.

2. Proved Undeveloped Reserves

At year-end 2010, approximately 7.7 billion oil-equivalent
barrels (GOEB) of ExxonMobils proved reserves were classified as proved undeveloped. This represents 31 percent of the 24.8 GOEB reported in proved reserves and includes approximately 1.0 GOEB of new proved undeveloped reserves related to the
acquisition of XTO. This compares to the 7.5 GOEB proved undeveloped or 33 percent of the proved reserves reported at the end of 2009. The net reduction in the percentage of proved undeveloped reserves from 2009 is reflective of our active
development programs on many projects worldwide which made significant progress in converting proved undeveloped reserves into proved developed reserves in 2010. During the year, ExxonMobil completed development work in over 80 fields and
participated in major project start-ups that resulted in the transfer of approximately 1.4 GOEB from proved undeveloped to proved developed reserves by year-end. This represented the movement of 18 percent of the proved undeveloped reserves
into the proved developed category or an average turnover time of about five years. The largest individual transfer was associated with the completion and startup of the Ras Laffan (3) Train 7 liquefied natural gas (LNG) train in Qatar.

One of ExxonMobils requirements for reporting proved
reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. Development
projects typically take two to four years from the time of first recording of proved reserves to the start of production of these reserves. However, the development time for large and complex projects can exceed five years. During 2010, new approved
projects added approximately 0.2 GOEB of proved undeveloped reserves. The largest of these was the Sakhalin 1 Arkutun Dagi development in Russia. Overall, investments of $19.4 billion were made by the Corporation during 2010 to progress the
development of reported proved undeveloped reserves, including $16.8 billion for oil and gas producing activities and an additional $2.6 billion for other non-oil and gas producing activities such as the construction of LNG trains, tankers and
regasification facilities that were undertaken to progress the development of proved undeveloped reserves. These investments represented 71 percent of the $27.3 billion in total reported Upstream capital and exploration expenditures.

Proved undeveloped reserves in Kazakhstan,
Netherlands, United States, Nigeria, and Canada have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure and the pace of co-venture/government funding, as well as the time required to complete
development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be affected by a number of factors including completion of development projects,
reservoir performance and regulatory approvals.

Approximately one third of the proved undeveloped reserves that have been reported for five or more years are in Kazakhstan and are related to two separate developments. The first is the initial
development of the giant offshore Kashagan field which is included in the North Caspian Production Sharing Agreement in which ExxonMobil participates. The second is the Tengizchevroil joint venture which includes a production license in the Tengiz
field and the nearby Korolev field. The joint venture is producing and proved undeveloped reserves will continue to move to proved developed as approved development phases progress.

The table below summarizes production by final product sold
and by geographic area for the last three years.

2010

2009

2008

(thousands of barrels daily)

Crude oil and natural gas liquids production

Consolidated Subsidiaries

United States

339

311

289

Canada/South America(1)

81

82

106

Europe

330

374

423

Africa

628

685

652

Asia

326

287

319

Australia/Oceania

58

65

67

Total Consolidated Subsidiaries

1,762

1,804

1,856

Equity Companies

United States

69

73

78

Europe

5

5

5

Asia

404

320

280

Total Equity Companies

478

398

363

Total crude oil and natural gas liquids production

2,240

2,202

2,219

Bitumen production

Consolidated Subsidiaries

Canada/South America

115

120

124

Synthetic oil production

Consolidated Subsidiaries

Canada/South America

67

65

62

Total liquids production

2,422

2,387

2,405

(millions of cubic feet daily)

Natural gas production available for sale

Consolidated Subsidiaries

United States

2,595

1,274

1,245

Canada/South America(1)

569

643

640

Europe

1,859

2,071

2,253

Africa

14

19

32

Asia

1,847

1,414

1,437

Australia/Oceania

332

315

358

Total Consolidated Subsidiaries

7,216

5,736

5,965

Equity Companies

United States

1

1

1

Europe

1,977

1,618

1,696

Asia

2,954

1,918

1,433

Total Equity Companies

4,932

3,537

3,130

Total natural gas production available for sale

12,148

9,273

9,095

(thousands of oil-equivalentbarrels daily)

Oil-equivalent production

4,447

3,932

3,921

(1)

South America includes liquids production for 2010, 2009 and 2008 of one thousand barrels daily for each year respectively and natural gas production available for sale
for 2010, 2009 and 2008 of 52 million, 58 million, and 63 million cubic feet daily for each year respectively.

Average production prices have been calculated by using sales quantities from the Corporations own production as the divisor.
Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A.
The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the
Oil and Gas Reserves part of the Supplemental Information on Oil and Gas Exploration and Production Activities portion of the Financial Section of this report due to volumes consumed or flared. Gas is converted to an
oil-equivalent basis at six million cubic feet per one thousand barrels.

Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude
bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in
Imperial Oil Limited. In 2010, the companys share of net production of synthetic crude oil was about 67,000 barrels per day. The Syncrude leases cover about 63 thousand acres in the Athabasca oil sands deposit.

Kearl Project

The Kearl project is a joint venture established to recover
shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil
Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 48 thousand acres in the Athabasca oil sands deposit.

The Kearl project is located approximately 40 miles north of
Fort McMurray, Alberta, Canada. Kearl is expected to be developed in two phases. Bitumen will be extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment plant. The product, a
blend of bitumen and diluent, is planned to be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by
pipeline. At year-end 2010, the initial development of the Kearl project was more than 50 percent complete with expected startup in 2012.

ExxonMobils year-end 2010 acreage holdings totaled
14.8 million net acres, of which 2.2 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. The acquisition of XTO Energy Inc. (XTO) was completed in 2010.

During 2010, 879.5 net exploration and development wells were
completed in the inland lower 48 states, including development activities in the Barnett Shale of North Texas, the Freestone Trend of East Texas, the Haynesville Shale of Texas and Louisiana, the Fayetteville Shale of Arkansas, the Woodford Shale of
Oklahoma, the Bakken oil play in North Dakota and Montana, the Marcellus Shale of Pennsylvania and West Virginia, the Eagle Ford Shale of South Texas, and the Piceance Basin of Colorado. Participation in Alaska production and development continued
and a total of 22.2 net exploration and development wells were completed.

ExxonMobils net acreage in the Gulf of Mexico at year-end 2010 was 2.1 million net acres. A total of 3.7 net exploration and development wells were completed during the year. The non-operated St.
Malo project in the Gulf of Mexico was approved in 2010. Offshore California 1.0 net development well was completed.

The Golden Pass LNG regasification terminal in Texas commenced operations in 2010. The terminal will have the capacity to deliver up to
two billion cubic feet of gas per day.

ExxonMobils year-end 2010 acreage holdings totaled
6.0 million net acres, of which 2.3 million net acres were offshore. A total of 129.0 net exploration and development wells were completed during the year. The Hibernia Southern Extension project development plan was approved in 2010.

In Situ Bitumen Operations

ExxonMobils year-end 2010 in situ bitumen acreage
holdings totaled 0.5 million net onshore acres. A total of 110.0 net development wells were completed during the year.

Argentina

ExxonMobils net acreage totaled 0.3 million onshore acres at year-end 2010, and there were 2.0 net development wells completed
during the year.

Venezuela

ExxonMobils acreage holdings and assets were
expropriated in 2007. Refer to the relevant portion of Note 15: Litigation and Other Contingencies of the Financial Section of this report for additional information.

EUROPE

Germany

A total of 4.8 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2010, with 7.3
net exploration and development wells completed during the year.

Netherlands

ExxonMobils net interest in licenses totaled approximately 1.6 million acres at year-end 2010, of which 1.2 million acres are onshore. A total of 3.0 net exploration and development wells
were completed during the year. The non-operated project to redevelop the Schoonebeek oil field was progressed.

Norway

ExxonMobils net interest in licenses at year-end 2010 totaled approximately 0.6 million acres, all offshore. ExxonMobil
participated in 3.5 net exploration and development well completions in 2010.

United Kingdom

ExxonMobils net interest in licenses at year-end 2010 totaled approximately 0.4 million acres, all offshore. A total of 2.9 net development wells were completed during the year. The South Hook
liquefied natural gas (LNG) terminal reached full capacity of two billion cubic feet per day in 2010.

ExxonMobils year-end 2010 acreage holdings totaled 0.6 million net offshore acres, and 2.2 net exploration and development
wells were completed during the year. The Angola Gas Gathering Project started up on-block gas handling in 2010, and project work continued on Kizomba Satellites Phase 1. On the non-operated Block 17, the Cravo-Lirio-Orquidea-Violeta project was
funded in 2010, while project execution continued at Pazflor. On the non-operated Block 31, project work continued on the Plutao-Saturno-Venus-Marte project.

ExxonMobils acreage totaled
0.1 million net offshore acres at year-end 2010, with 5.3 net development wells completed during the year.

Nigeria

ExxonMobils net acreage totaled 1.0 million offshore acres at year-end 2010, with 9.4 net exploration and development wells
completed during the year. Work continued on the deepwater Usan project in 2010. A 3-D seismic acquisition program was completed on the Nigerian Shelf joint venture acreage.

ASIA

Azerbaijan

At year-end 2010, ExxonMobils net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 60 thousand acres. At the
Azeri-Chirag-Gunashli field, 0.6 net development wells were completed. The Chirag Oil Project was funded in 2010, and project activities are under way.

Indonesia

At year-end 2010, ExxonMobil had 4.4 million net acres, 3.3 million net acres offshore and 1.1 million net acres onshore. A
total of 0.8 net exploration wells were completed during the year.

Iraq

At year-end 2010, ExxonMobils onshore acreage was 87 thousand net acres. During 2010, a contract was signed with South Oil Company of the Iraqi Ministry of Oil to redevelop and expand the West
Qurna (Phase 1) oil field. The term of the contract is 20 years with the right to extend for five years. In 2010 initial field rehabilitation activities commenced. Field rehabilitation activities across the life of this project will include drilling
of new wells, working over of existing wells, optimization and debottlenecking of existing facilities, and the establishment of field offices and camps.

Kazakhstan

ExxonMobils net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2010, with 0.2 net
development wells completed during 2010. Working with our partners, construction of the initial phase of the Kashagan field continued during 2010.

ExxonMobil has interests in production sharing contracts
covering 0.5 million net acres offshore Malaysia at year-end 2010. During the year, a total of 5.1 net exploration and development wells were completed.

ExxonMobils net acreage holdings at year-end 2010 were 85 thousand acres, all offshore. A total of 1.5 net development wells were completed at the Sakhalin-1 Odoptu field during the year which
started production in 2010. The Sakhalin-1 Chayvo Expansion and Arkutun-Dagi projects were both funded in 2010, and project activities are under way.

ExxonMobils net acreage in the Abu Dhabi offshore
Upper Zakum oil concession was 81 thousand acres at year end 2010. During the year, 0.6 net development wells were completed, as rig activity focused mainly on workovers and injection wells.

ExxonMobils net acreage in the Abu Dhabi onshore oil
concession was 0.5 million acres at year-end 2010, of which 0.4 million acres are onshore. During the year, a total of 4.3 net development wells were completed.

AUSTRALIA/OCEANIA

Australia

ExxonMobils net year-end 2010 offshore acreage
holdings totaled 1.7 million acres. During 2010, a total of 5.3 net exploration and development wells were drilled. Offshore installation commenced for the Kipper Tuna Turrum project.

Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project
progressed in 2010. The project consists of a subsea infrastructure for offshore production and transportation of the gas, and a 15 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow
Island, Western Australia.

A total of 0.4 million net onshore acres were held by ExxonMobil at year-end 2010, with 0.4 net
development wells completed during the year. In 2010, the Papua New Guinea liquefied natural gas project commenced construction activities. The project consists of conditioning facilities in the southern PNG Highlands, a 6.6 million tonnes per
year LNG facility near Port Moresby and approximately 450 miles of onshore and offshore pipelines.

WORLDWIDE EXPLORATION

At year-end 2010, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 40.6 million net
acres were held at year-end 2010, and 2.6 net exploration wells were completed during the year in these countries.

6. Delivery Commitments

ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may
specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own
production and the spot market. Worldwide, we are contractually committed to deliver approximately 17 million barrels of crude oil and 3,900 billion cubic feet of natural gas for the period from 2011 through 2013. We expect to fulfill the majority
of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and spot market purchases as necessary.

There were 35,691 gross and
30,494 net operated wells at year-end 2010 and 16,587 gross and 13,737 net operated wells at year-end 2009. The number of wells with multiple completions was 1,725 gross in 2010 and 1,039 gross in 2009.

B. Gross and Net Developed Acreage

Year-end 2010

Year-end 2009

Gross

Net

Gross

Net

(thousands of acres)

Gross and Net Developed Acreage

Consolidated Subsidiaries

United States

16,621

9,861

9,866

5,061

Canada/South America(1)

5,450

2,439

5,570

2,460

Europe

3,956

1,630

5,359

2,454

Africa

1,772

684

1,958

758

Asia

1,411

623

1,226

512

Australia/Oceania

1,955

719

1,956

719

Total Consolidated Subsidiaries

31,165

15,956

25,935

11,964

Equity Companies

United States

137

58

165

59

Europe

4,363

1,356

4,325

1,352

Asia

5,818

648

5,817

648

Total Equity Companies

10,318

2,062

10,307

2,059

Total gross and net developed acreage

41,483

18,018

36,242

14,023

(1)

Includes gross and net developed acreage in South America of 618 gross and 202 net thousands of acres for 2010 and 618 gross and 202 net thousands of acres for 2009.

Separate acreage data for oil and
gas are not maintained because, in many instances, both are produced from the same acreage.

Includes gross and net undeveloped acreage in South America of 10,111 gross and 7,442 net thousands of acres for 2010 and 12,005 gross and 11,800 net thousands of acres
for 2009.

ExxonMobils
investment in developed and undeveloped acreage is comprised of numerous concessions, blocks and leases. The terms and conditions under which the Corporation maintains exploration and/or production rights to the acreage are property-specific,
contractually defined and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, the Corporation may elect to
relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Corporation has
generally been successful in obtaining extensions. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a material adverse impact on the Corporation.

D. Summary of Acreage Terms

UNITED STATES

Oil and gas leases have an exploration period ranging from
one to ten years, and a production period that normally remains in effect until production ceases. Under certain circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances, a fee
interest is acquired where both the surface and the underlying mineral interests are owned outright.

CANADA / SOUTH AMERICA

Canada

Exploration permits are granted for varying periods of time with renewals possible. Exploration rights in onshore areas acquired from Canadian provinces entitle the holder to obtain leases upon

completing specified work. In general, production leases are held as long as there is production on the lease. The majority of Cold Lake leases are held in this manner. The exploration acreage in
eastern Canada and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.

Argentina

The federal onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the
second exploration period and up to two years for the third exploration period. A 50-percent relinquishment is required after each exploration period. An extension after the third exploration period is possible for up to five years. The total
production term is 25 years with a ten-year extension possible, once a field has been developed. Argentine provinces are entitled to modify the concession terms granted within their territories. The exploration permit granted by Neuquen Province to
an ExxonMobil affiliate in 2010 fixed the initial exploration period at three years, the second at two years and the third at one year, and one of these periods can be extended for an additional year.

EUROPE

Germany

Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions of up to three
years each. Extensions are subject to specific, minimum work commitments. Production licenses are normally granted for 20 to 25 years with multiple possible extensions as long as there is production on the license. In 2007, ExxonMobil affiliates
acquired four exploration licenses in the state of Lower Saxony. The exploration licenses are for a period of five years during which exploration work programs will be carried out. In 2009, ExxonMobil affiliates acquired two exploration licenses in
the state of North Rhine Westphalia for an initial period of five years and an extension to one of the Lower Saxony licenses.

Netherlands

Under the Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a
period as explicitly defined in the license. The term is based on the period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the Mining Law.

Production rights granted prior to January 1, 2003, remain
subject to their existing terms, and differ slightly for onshore and offshore areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined in the license, ranging from 35 to
45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976 they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years.

Norway

Licenses issued prior to 1972 were for an initial period of
six years and an extension period of 40 years, with relinquishment of at least one-fourth of the original area required at the end of the sixth year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were for
an initial period of up to six years (with extension of the initial period of one year at a time up to ten years after 1985), and an extension period of up to 30 years, with relinquishment of at least one-half of the original area required at the
end of the initial period. Licenses issued after July 1, 1997, have an

initial period of up to ten years and a normal extension period of up to 30 years or in special cases of up to 50 years, and with relinquishment of at least one-half of the original area required
at the end of the initial period.

United
Kingdom

Acreage terms are fixed by the
government and are periodically changed. For example, many of the early licenses issued under the first four licensing rounds provided for an initial term of six years with relinquishment of at least one-half of the original area at the end of the
initial term, subject to extension for a further 40 years. At the end of any such 40-year term, licenses may continue in producing areas until cessation of production; or licenses may continue in development areas for periods agreed on a
case-by-case basis until they become producing areas; or licenses terminate in all other areas. The licensing regime was last updated in 2002, and the majority of licenses issued have an initial term of four years with a second term extension of
four years and a final term of 18 years with a mandatory relinquishment of 50 percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.

AFRICA

Angola

Exploration and production activities are governed by production sharing agreements with an initial exploration term of four years and an
optional second phase of two to three years. The production period is for 25 years, and agreements generally provide for a negotiated extension.

Chad

Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and
conditions of the permits, including relinquishment obligations, are specified in a negotiated convention. The production term is for 30 years and may be extended at the discretion of the government.

Equatorial Guinea

Exploration and production activities are governed by
production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy. The exploration periods are for ten to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil
is 30 years while the production period for gas is 50 years. A new Hydrocarbons Law was enacted in November 2006. Under the new law, the exploration terms for new production sharing contracts are four to five years with a maximum of two one-year
extensions, unless the Ministry agrees otherwise.

Nigeria

Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with
the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year
exploration period (an initial exploration phase plus one or two optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the ten-year
exploration period, and OMLs have a 20-year production period that may be extended.

Some exploration activities are carried out in deepwater by joint ventures with local
companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for ten years and are non-renewable, while in all other areas the licenses are for five years and also are non-renewable. Demonstrating a commercial discovery is the
basis for conversion of an OPL to an OML.

OMLs
granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onshore and 40 years in offshore areas and have been renewed, effective December 1, 2008, for a further period of
20 years, with a further renewal option of 20 years. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC. In 2000, a Memorandum of Understanding (MOU) was executed defining commercial terms
applicable to existing joint venture oil production. The MOU may be terminated on one calendar years notice.

OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for
onshore or offshore location and are renewable, upon 12 months written notice, for another period of 20 years. OMLs not held by NNPC are also subject to a mandatory 50-percent relinquishment after the first ten years of their duration.

ASIA

Azerbaijan

The production sharing agreement (PSA) for the development
of the Azeri-Chirag-Gunashli field is established for an initial period of 30 years starting from the PSA execution date in 1994.

Other exploration and production activities are governed by PSAs negotiated with the national oil company of Azerbaijan. The exploration
period consists of three or four years with the possibility of a one to three-year extension. The production period, which includes development, is for 25 years or 35 years with the possibility of one or two five-year extensions.

Indonesia

Exploration and production activities in Indonesia are
generally governed by cooperation contracts, usually in the form of a production sharing contract, negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. Formerly this activity was carried out by
Pertamina, the government owned oil company, which is now a competing limited liability company.

Iraq

Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of the Iraq Ministry of Oil. An ExxonMobil affiliate entered into a
contract with South Oil Company of the Ministry of Iraq for the rights to participate in the development and production activities of the West Qurna (Phase I) oil and gas field effective March 1, 2010. The term of the contract is 20 years with
the right to extend for 5 years.

Kazakhstan

Onshore exploration and production
activities are governed by the production license, exploration license and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.

Offshore exploration and production activities are governed
by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for
20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.

Exploration and production activities are governed by
production sharing contracts (PSCs) negotiated with the national oil company. The more recent PSCs governing exploration and production activities have an overall term of 24 to 38 years, depending on water depth, with possible extensions to the
exploration and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries will be deemed relinquished. The development period is from four to six
years from commercial discovery, with the possibility of extensions under special circumstances. Areas from which commercial production has not started by the end of the development period will be deemed relinquished if no extension is granted. All
extensions are subject to the national oil companys prior written approval. The total production period is 15 to 25 years from first commercial lifting, not to exceed the overall term of the contract.

In 2008, the Company reached agreement with the national oil
company for a new PSC, which was subsequently signed in 2009. Under the new PSC, from 2008 until March 31, 2012, the Company is entitled to undertake new development and production activities in oil fields under an existing PSC, subject to new
minimum work and spending commitments, including an enhanced oil recovery project in one of the oil fields. When the existing PSC expires on March 31, 2012, the producing fields covered by the existing PSC will automatically become part of the new
PSC, which has a 25-year duration from April 2008.

Qatar

The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit the
economic development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects.

Republic of Yemen

The Jannah production sharing agreement has a development period extending 20 years from first commercial declaration, which was made in
June 1995.

Russia

Terms for ExxonMobils acreage are fixed by the
production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, which would be
2021. The term may be extended thereafter in 10-year increments as specified in the PSA.

Thailand

The Petroleum Act of 1971 allows production under ExxonMobils concession for 30 years with a ten-year extension at terms generally prevalent at the time.

United Arab Emirates

Exploration and production activities for the major onshore
oil fields in the Emirate of Abu Dhabi are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi. An interest in the Upper Zakum field, a major offshore
field, was acquired effective as of January 2006, for a term expiring March 2026.

Exploration and production activities conducted offshore in
Commonwealth waters are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for resources that are not commercially viable at
the time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a
further renewal of 21 years and thereafter indefinitely, i.e., for the life of the field. Effective from July 1998, new production licenses are granted indefinitely. In each case, a production license may be terminated if no
production operations have been carried on for five years.

Papua New Guinea

Exploration and production activities are governed by the Oil and Gas Act. Petroleum Prospecting licenses are granted for an initial term of six years with a five-year extension possible (an additional
extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum Development licenses are granted for an initial
25-year period. An extension of up to 20 years may be granted at the Ministers discretion. Petroleum Retention licenses may be granted for gas resources that are not commercially viable at the time of application, but may become commercially
viable within the maximum possible retention time of 15 years. Petroleum Retention licenses are granted for five-year terms, and may be extended, at the Ministers discretion, twice for the maximum retention time of 15 years. Extensions of
Petroleum Retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at the time of extension that the resources could become commercially viable in less than five years.

ExxonMobils Downstream segment manufactures and sells
petroleum products. The refining and supply operations encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants and other products and feedstocks to our customers
around the world.

Refining
Capacity At Year-End 2010 (1)

ExxonMobilShare KBD (2)

ExxonMobilInterest
%

United States

Torrance

California

150

100

Joliet

Illinois

238

100

Baton Rouge

Louisiana

504

100

Baytown

Texas

561

100

Beaumont

Texas

345

100

Other (2 refineries)

155

Total United States

1,953

Canada

Strathcona

Alberta

189

69.6

Dartmouth

Nova Scotia

83

69.6

Nanticoke

Ontario

113

69.6

Sarnia

Ontario

121

69.6

Total Canada

506

Europe

Antwerp

Belgium

307

100

Fos-sur-Mer

France

119

82.9

Port-Jerome-Gravenchon

France

233

82.9

Karlsruhe

Germany

78

25

Augusta

Italy

198

100

Trecate

Italy

174

74.1

Rotterdam

Netherlands

191

100

Slagen

Norway

116

100

Fawley

United Kingdom

329

100

Total Europe

1,745

Asia Pacific

Kawasaki

Japan

296

50.1

Sakai

Japan

139

50.1

Wakayama

Japan

160

50.1

Jurong/PAC

Singapore

605

100

Sriracha

Thailand

174

66

Other (5 refineries)

337

Total Asia Pacific

1,711

Other Non-U.S.

Yanbu

Saudi Arabia

200

50

Laffan

Qatar

14

10

Other (4 refineries)

131

Total Other Non-U.S.

345

Total Worldwide

6,260

(1)

Capacity data is based on 100 percent of rated refinery process unit stream-day capacities under normal operating conditions, less the impact of shutdowns for
regular repair and maintenance activities, averaged over an extended period of time.

(2)

Thousands of barrels per day (KBD). ExxonMobil share reflects 100 percent of atmospheric distillation capacity in operations of ExxonMobil and majority-owned
subsidiaries. For companies owned 50 percent or less, ExxonMobil share is the greater of ExxonMobils equity interest or that portion of distillation capacity normally available to ExxonMobil.

Regarding a matter previously
reported in the Corporations Form 10-Q for the second quarter of 2010, ExxonMobil Oil Corporations Beaumont, Texas refinery entered into an Agreed Order with the Texas Commission on Environmental Quality on November 15, 2010 and paid a
civil penalty of $106 thousand to resolve Notices of Violation issued in January and February 2010 relating to six alleged violations of air emission regulations.

With regard to the matter most recently reported in the
Corporations Form 10-Q for the second quarter of 2007, the New York State Attorney General, Exxon Mobil Corporation and ExxonMobil Oil Corporation have agreed to enter into a Consent Decree to resolve issues relating to alleged contamination
at ExxonMobils former Brooklyn, New York terminal and refinery. The Consent Decree was lodged in the U.S. District Court for the Eastern District of New York on November 17, 2010 and was subject to public comment until January 25, 2011. On
January 24, 2011, the United States Department of Justice filed the only comments, which sought clarification of some elements of the Consent Decree. Those comments have been incorporated into the Consent Decree, which is subject to review and
approval by the Court. If approved, the Consent Decree would require ExxonMobil to undertake actions to investigate and remediate certain environmental conditions at the Brooklyn terminal and refinery, pay $19.5 million to fund Environmental Benefit
Projects to benefit the Greenpoint Community; pay a civil penalty of $250 thousand; pay $250 thousand for Natural Resources Damages Restoration Projects; pay past costs of the State for oversight of, investigation and remedial activities in the
amount of $1.5 million and pay future State oversight costs, up to $3.5 million.

On November 29, 2010, XTO Energy Inc. received a Notice of Violation (NOV) from the Pennsylvania Department of Environmental Protection (PaDEP) alleging that an unpermitted discharge of brine or produced
fluid occurred from a tank located at the Marquardt Well Site in Penn Township, Pennsylvania, which discharge reached a water of the State and that XTO failed to notify the PaDEP of the incident, had litter on the site, and failed to post well
permit numbers and operator information at the well site. The NOV does not contain a specific penalty demand, but XTO believes that PaDEP may seek a penalty in excess of $100 thousand. XTO responded to the NOV on December 9, 2010 and, while not
admitting to a violation for the alleged release, agreed to cooperate with PaDEP in responding to and remediating it.

As reported in the Corporations 2009 Form 10-K, in October 2009, a purported shareholder complaint captioned Resnik v.
Boskin et al., alleging direct and derivative claims, was filed in the United States District Court for the District of New Jersey, naming the directors serving at the time, the named executive officers listed in the
Corporations 2009 Proxy Statement (as defined in Securities and Exchange Commission regulations) and ExxonMobil as defendants. The complaint was amended in December 2009, alleging that the defendants made materially false or misleading proxy
solicitations in connection with the 2008 and 2009 shareholder votes regarding the election of directors and failed to seek stockholder reapproval of the Exxon Mobil Corporation 2003 Incentive Program to qualify certain incentive compensation paid
to the named executive officers as properly deductible expenditures. The amended complaint seeks various injunctive remedies, including corrective disclosure, new election of directors after corrective disclosure, enjoining candidates from serving
on the Board until a new election occurs, stockholder reapproval of the program, enjoining payments under the program and short term incentive program to the named executive officers, damages (the amount of which is not specified) from the
individual defendants in favor of ExxonMobil, and costs and expenses of the action. The defendants moved to dismiss the lawsuit on several grounds, including that the plaintiffs allegations concerning the Corporations proxy solicitations
do not state claims under the federal securities laws and that the plaintiffs derivative claims cannot stand since the plaintiff failed to make a demand on the Corporation or allege facts that would excuse a demand. The motion was argued to
the district court in August 2010. On February 17, 2011, the court granted defendants motion to dismiss, finding fatal flaws in the plaintiffs three causes of action. Notably, the court determined that

the Internal Revenue Code and Treasury Regulations did not require the Corporation to seek stockholder reapproval of its incentive programs at the time it distributed the 2008 and 2009 proxy
statements. Notwithstanding the plaintiffs dismissal, the court granted the plaintiff 21 days to amend the three causes of action. If the plaintiff does not timely amend, plaintiff will have 30 days thereafter to file a notice of appeal.

Refer to the relevant portions of
Note 15: Litigation and Other Contingencies of the Financial Section of this report for additional information on legal proceedings.

Mr. Rex W. Tillerson became a Director and President of Exxon Mobil Corporation on March 1, 2004. He became Chairman of the
Board and Chief Executive Officer on January 1, 2006. He still holds these positions as of this filing date.

Mark W. Albers

Senior Vice President

Held current title since:

April 1, 2007

Age: 54

Mr. Mark W. Albers was President of ExxonMobil Development Company October 1, 2004  April 13, 2007. He became
Senior Vice President of Exxon Mobil Corporation on April 1, 2007, a position he still holds as of this filing date.

Michael J. Dolan

Senior Vice President

Held current title since:

April 1, 2008

Age: 57

Mr. Michael J. Dolan was President of ExxonMobil Chemical Company September 1, 2004  March 31, 2008. He was Vice
President of Exxon Mobil Corporation September 1, 2004  March 31, 2008. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2008, a position he still holds as of this filing date.

Donald D. Humphreys

Senior Vice President and Treasurer

Held current title since:

January 25, 2006 (Senior Vice President)

July 1, 2004 (Treasurer)

Age: 63

Mr. Donald D. Humphreys was Vice President and Controller of Exxon Mobil Corporation (formerly Exxon Corporation) July 1,
1997  June 30, 2004. He was the Vice President and Treasurer of Exxon Mobil Corporation July 1, 2004  January 24, 2006. He became Senior Vice President and Treasurer of Exxon Mobil Corporation on January 25, 2006, positions he still
holds as of this filing date.

Andrew P. Swiger

Senior Vice President

Held current title since:

April 1, 2009

Age: 54

Mr. Andrew P. Swiger was Executive Vice President of ExxonMobil Production Company May 1, 2004  September 30, 2006.
He was President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation October 1, 2006  March 31, 2009. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a
position he still holds as of this filing date.

Mr. S. Jack Balagia was Assistant General Counsel of Exxon Mobil Corporation April 1, 2004 to March 1, 2010. He became Vice
President and General Counsel of Exxon Mobil Corporation on March 1, 2010, a position he still holds as of this filing date.

William M. Colton

Vice President - Strategic Planning

Held current title since:

February 1, 2009

Age: 57

Mr. William M. Colton was Assistant Treasurer of Exxon Mobil Corporation January 25, 2006 to January 31, 2009. He became
Vice PresidentStrategic Planning of Exxon Mobil Corporation on February 1, 2009, a position he still holds as of this filing date.

Harold R. Cramer

Vice President

Held current title since:

November 30, 1999

Age: 60

Mr. Harold R. Cramer became President of ExxonMobil Fuels Marketing Company and Vice President of Exxon Mobil Corporation on
November 30, 1999, positions he still holds as of this filing date.

Neil W. Duffin

President, ExxonMobil Development Company

Held current title since:

April 13, 2007

Age: 54

Mr. Neil W. Duffin was Vice President of ExxonMobil Production Company July 1, 2004  August 31, 2006. He was
Executive Vice President of ExxonMobil Development Company September 1, 2006  April 13, 2007, becoming President on April 13, 2007, a position he still holds as of this filing date.

Robert S. Franklin

Vice President

Held current title since:

May 1, 2009

Age: 53

Mr. Robert S. Franklin was Vice President, New Business Development of ExxonMobil Gas & Power Marketing Company
July 1, 2001  April 15, 2007. He was Executive Assistant to the Chairman, Exxon Mobil Corporation April 16, 2007  March 31, 2008. He was Vice President, Europe/Russia/Caspian of ExxonMobil Production Company April 1, 2008
 May 1, 2009. He became Vice President of Exxon Mobil Corporation and President, ExxonMobil Upstream Ventures on May 1, 2009, positions he still holds as of this filing date.

Sherman J. Glass, Jr.

Vice President

Held current title since:

April 1, 2008

Age: 63

Mr. Sherman J. Glass, Jr. was Senior Vice President of ExxonMobil Chemical Company September 1, 2005  March 31, 2008.
He became President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation on April 1, 2008. He still holds these positions as of this filing date.

Mr. Stephen M. Greenlee was Vice President of ExxonMobil Exploration Company June 1, 2004  June 1, 2009. He was
President of ExxonMobil Upstream Research Company June 1, 2009  August 31, 2010. He became President of ExxonMobil Exploration Company and Vice President of Exxon Mobil Corporation on September 1, 2010, positions he still holds as of
this filing date.

Alan J. Kelly

Vice President

Held current title since:

December 1, 2007

Age: 53

Mr. Alan J. Kelly was Manager, Global Logistics of ExxonMobil Refining & Supply Company February 1, 2005 
February 28, 2006. He was on Special Assignment for the National Petroleum Council March 1, 2006  November 30, 2007. He became President of ExxonMobil Lubricants & Petroleum Specialties Company and Vice President of
Exxon Mobil Corporation on December 1, 2007. He still holds these positions as of this filing date.

Richard M. Kruger

Vice President

Held current title since:

April 1, 2008

Age: 51

Mr. Richard M. Kruger was Vice President of ExxonMobil Production Company January 1, 2003  September 30, 2006,
and then Executive Vice President October 1, 2006  March 31, 2008. He became President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on April 1, 2008. He still holds these positions as of this
filing date.

Patrick T. Mulva

Vice President and Controller

Held current title since:

February 1, 2002 (Vice President)

July 1, 2004 (Controller)

Age: 59

Mr. Patrick T. Mulva was Vice PresidentInvestor Relations and Secretary of Exxon Mobil Corporation February 1, 2002
 July 1, 2004. On July 1, 2004, he became Vice President and Controller, positions he still holds as of this filing date.

Stephen D. Pryor

Vice President

Held current title since:

December 1, 2004

Age: 61

Mr. Stephen D. Pryor was President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil
Corporation December 1, 2004  March 31, 2008. He became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing
date.

Mr. David S. Rosenthal was Controller of ExxonMobil Production Company April 1, 2002  May 31, 2006. He was
Assistant Controller of Exxon Mobil Corporation on June 1, 2006  September 30, 2008. He became Vice PresidentInvestor Relations and Secretary of Exxon Mobil Corporation on October 1, 2008, positions he still holds as of
this filing date.

James M. Spellings, Jr.

Vice President and General Tax Counsel

Held current title since:

March 1, 2010

Age: 49

Mr. James M. Spellings, Jr. was General ManagerCorporate Planning of Exxon Mobil Corporation February 1, 2005 
March 31, 2007, and then Associate General Tax Counsel April 1, 2007  March 1, 2010. He became Vice President and General Tax Counsel on March 1, 2010, positions he still holds as of this filing
date.

Thomas R. Walters

Vice President

Held current title since:

April 1, 2009

Age: 56

Mr. Thomas R. Walters was President of Global Services Company from September 1, 2005  April 4, 2007. He was
Executive Vice President of ExxonMobil Development Company April 13, 2007  April 1, 2009. He became President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on April 1, 2009,
positions he still holds as of this filing date.

Jack P. Williams, Jr.

President, XTO Energy Inc.

Held current title since:

June 25, 2010

Age: 47

Mr. Jack P. Williams, Jr. was Upstream Advisor, Exxon Mobil Corporation July 1, 2005  May 1, 2007. He was Vice
President, Engineering, ExxonMobil Production Company May 1, 2007  April 30, 2009. He was Vice President of ExxonMobil Development Company May 1, 2009  July 1, 2010. He became President of XTO Energy Inc. on
June 25, 2010, a position he still holds as of this filing date.

Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.

Note 1On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset shares issued in conjunction with company benefit
plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. Repurchases were temporarily suspended due to regulatory requirements in connection with the XTO transaction.
The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. In its most recent earnings release dated January 31, 2011, the Corporation stated that first quarter 2011
share purchases are continuing at a pace consistent with fourth quarter 2010 share reduction spending of $5 billion. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or
discontinued at any time without prior notice.

Item 6. Selected Financial Data.

Years Ended December 31,

2010
(1)

2009

2008

2007

2006

(millions of dollars, except per share amounts)

Sales and other operating revenue (2)

$

370,125

$

301,500

$

459,579

$

390,328

$

365,467

(2) Sales-based taxes included.

$

28,547

$

25,936

$

34,508

$

31,728

$

30,381

Net income attributable to ExxonMobil

$

30,460

$

19,280

$

45,220

$

40,610

$

39,500

Earnings per common share

$

6.24

$

3.99

$

8.70

$

7.31

$

6.64

Earnings per common share - assuming
dilution

$

6.22

$

3.98

$

8.66

$

7.26

$

6.60

Cash dividends per common share

$

1.74

$

1.66

$

1.55

$

1.37

$

1.28

Total assets

$

302,510

$

233,323

$

228,052

$

242,082

$

219,015

Long-term debt

$

12,227

$

7,129

$

7,025

$

7,183

$

6,645

(1)

See Note 19: Acquisition of XTO Energy Inc. contained in the Financial Section of this report.

Item
7.Managements Discussion and Analysis of Financial Condition and Results of Operations.

Reference is made to the section entitled Managements Discussion and Analysis of Financial Condition and Results of
Operations in the Financial Section of this report.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Reference is made to the section
entitled Market Risks, Inflation and Other Uncertainties, excluding the part entitled Inflation and Other Uncertainties, in the Financial Section of this report. All statements other than historical information incorporated
in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.

Item
8. Financial Statements and Supplementary Data.

Reference is made to the following in the Financial Section of this report:



Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 25, 2011, beginning with the section
entitled Report of Independent Registered Public Accounting Firm and continuing through Note 19: Acquisition of XTO Energy Inc.;



Quarterly Information (unaudited);



Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited); and



Frequently Used Terms (unaudited).

Financial Statement Schedules have been omitted because they
are not applicable or the required information is shown in the consolidated financial statements or notes thereto.

Item 9. Changes in and Disagreements With
Accountants on Accounting and Financial Disclosure.

As
indicated in the certifications in Exhibit 31 of this report, the Corporations chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporations disclosure controls and procedures as of
December 31, 2010. Based on that evaluation, these officers have concluded that the Corporations disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it
files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is
recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commissions rules and forms.

Managements Report on Internal Control Over Financial Reporting

Management, including the Corporations chief executive
officer, principal financial officer and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporations financial reporting. Management conducted an evaluation of the effectiveness
of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that
Exxon Mobil Corporations internal control over financial reporting was effective as of December 31, 2010.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporations internal
control over financial reporting as of December 31, 2010, as stated in their report included in the Financial Section of this report.

Changes in Internal Control Over Financial Reporting

There were no changes during the Corporations last fiscal quarter that materially affected, or are reasonably likely to materially
affect, the Corporations internal control over financial reporting.

Item 9B. Other Information.

Effective April 1, 2011, the annual salary for
Michael J. Dolan will increase to $1,010,000. Like all other ExxonMobil executive officers, Mr. Dolan is an at will employee of the Corporation and does not have an employment contract.

PART III

Item
10. Directors, Executive Officers and Corporate Governance.

Incorporated by reference to the following from the registrants definitive proxy statement for the 2011 annual meeting of
shareholders (the 2011 Proxy Statement):

The information required under Item 403 of Regulation S-K is incorporated by reference to the sections Director and Executive
Officer Stock Ownership and Certain Beneficial Owners of the registrants 2011 Proxy Statement.

Equity Compensation Plan Information

(a)

(b)

(c)

Plan Category

Number of Securities to beIssued Upon Exercise ofOutstanding
Options,Warrants and Rights

The exercise price of each option reflected in this table is equal to the fair market value of the Companys common stock on the date the option was granted. The
weighted-average price reflects one prior option grant that is still outstanding.

(2)

Includes 19,578,656 options granted under the 1993 Incentive Program and 9,533,221 restricted stock units to be settled in shares.

(3)

Does not include options that ExxonMobil assumed in the 2010 merger with XTO Energy Inc. At year-end 2010, the number of securities to be issued upon exercise of
outstanding options under XTO Energy Inc. plans was 9,929,860, and the weighted-average exercise price of such options was $59.51. No additional awards may be made under those plans.

(4)

Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 141,939,056 shares available for award under the 2003
Incentive Program and 742,700 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.

(5)

Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adopted by the Board, each
non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 2,500 restricted shares each following year. While on the Board, each non-employee
director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director leaves the Board early.

Information provided in response to this Item 13 is incorporated by reference to the portions entitled Related Person Transactions and Procedures and Director Independence of the
section entitled Corporate Governance of the registrants 2011 Proxy Statement.

Item 14. Principal Accounting Fees and Services.

Incorporated by reference to the portion entitled
Audit Committee of the section entitled Corporate Governance and the section entitled Ratification of Independent Auditors of the registrants 2011 Proxy Statement.